Natural gas from many gas fields, which is often produced at high pressures, possibly as high as 50 MPa, can contain significant levels of H2O, H2S, CO2, N2, mercaptans, and/or heavy hydrocarbons that have to be removed to various degrees before the gas can be transported to market. It is preferred that as much of the acid gases H2S and CO2 be removed from natural gas as possible to leave methane as the recovered component. Small increases in recovery of this light component can result in significant improvements in process economics and also serve to prevent unwanted resource loss. It is desirable to recover more than 80 vol %, preferably more than 90 vol %, of the methane when detrimental impurities are removed. In many instances effective removal of the H2S is more important than CO2 removal as specifications for natural gas transmission pipelines typically limit the H2S content to be as low as 4 vppm while a more relaxed specification of two to three percent is typically permissible for CO2. If the contaminant removal process is unselective between these two gases or favorable to CO2 removal, the treatment will be unnecessarily severe, resulting in increased processing costs. A natural gas treatment process which is selective for H2S relative to CO2 is therefore economically attractive.
Natural gas treating is often carried out using solid sorbents such as activated charcoal, silica gel, activated alumina, or various zeolites. The well-established pressure swing adsorption (PSA) process has been used in this way since about the 1960s. In the PSA process, the solid sorbent is contained in a vessel and adsorbs the contaminant gas species at high pressure and when the design sorption capacity of the sorbent is attained the gas stream is switched to another sorption vessel while the pressure in the first vessel is reduced to desorb the adsorbent component. A stripping step with inert (non-reactive) as or with treated product gas may then follow before the vessel is returned to the sorption portion of the cycle. Variants of the conventional PSA (cPSA) process have been developed including the partial pressure swing or displacement purge adsorption (PPSA), rapid cycle pressure swing adsorption (RCPSA), Dual Bed (or Duplex) PSA Process, and rapid cycle partial pressure swing or displacement purge adsorption (RCPPSA) technologies.
Temperature swing adsorption (TSA) provides an alternative to the pressure swing technology in which the sorbed component is desorbed by an increase in temperature typically achieved by the admission of high temperature gas, e.g., air, to the vessel in the regeneration phase. Rapid cycle thermal swing adsorption (RCTSA) is a variant of the conventional TSA process using short cycles, typically less than two minutes. TSA processes are generally available commercially from a number of technology suppliers, although the state of the art for large scale rapid cycle TSA units is considerably less advanced. Large scale slow (˜10 hr) cycle internally heated TSA's have been used in natural gas processing for rigorous dehydration and mercaptan removal. In an internally heated thermal swing adsorption process, the gas or fluid used to heat the contactor directly contacts the adsorbent material. As such, the gas or fluid used to heat the contactor during regeneration can pass through the same channels that the feed gas does during the adsorption step. Externally heated thermal swing adsorption processes employ contactors having a separate set of channels to carry gases or fluids used to heat and cool the contactor so that gases used to heat and cool the contactor do not mix with the adsorbent that contacts the feed gas.
Other gas streams containing similar contaminants are encountered in various industrial processes, notably in petroleum refining and in petrochemical processes. In petroleum refining, for example, hydrodesulfurization processes utilize separation processes which remove the hydrogen sulfide formed in the process from the circulating stream of hydrogen. Conventionally, amine scrubbers are used for this purpose, using liquid amine sorbents such as monoethanolamine (MEA), diethanolamine (DEA), triethanolamine (TEA), methyldiethanolamine (MDEA), and diisopropylamine (DIPA) in the form of an aqueous solution.
Conventionally, liquid sorbent systems such as used in hydrogen sulfide scrubbing operate on a closed cycle with separate sorption and regeneration vessels through which the liquid sorbent is continuously circulated in a sorption-regeneration loop in which the sorption is typically carried out at a temperature optimized for sorption of the contaminant and the regeneration carried out by stripping, usually by steam at a higher temperature, in the regeneration tower. Inert gas stripping is also potentially useful to remove the sorbed contaminant species.
The capture of CO2 by amine species takes place through the formation of carbamate salts for primary and secondary amines, and additionally through the formation of ammonium bicarbonate salts when water is present. When tertiary amines are utilized with water present the formation of carbamate salts which require a proton transfer cannot take place and the reactions are limited to the formation of bicarbonate salts in a reaction sequence which with requires H2O to be present. In the absence of water, tertiary and other non-protogenic basic nitrogen species do not react with CO2, as no bicarbonate formation is possible. Hydrogen sulfide (H2S) is a Brønsted acid, and it reacts with all sufficiently basic amine species, including tertiary or non-protogenic amines, amidines, guanidines, and biguanides through simple acid/base reactions by the transfer of a proton from the H2S to the amine species to form ammonium sulfide (trisubstituted ammonium sulfide salts in the case of tertiary amines) reversibly, both in the presence and absence of water.